A key element in successful hydrocarbon exploration is the existence of adequate source rock in the basin, in terms of both total organic content (TOC) and level of organic metamorphism (LOM) or “maturity”. In undrilled or poorly explored basins, source adequacy is essentially unknown and is a major exploration risk. However, once a well is drilled, a formation evaluation method called Delta Log R (or Δ Log R) is available to assess source rock quality, using overlays of suitably scaled resistivity log and sonic log (or density log) data. See Passey et al., “A Practical Model for Organic Richness from Porosity and Resistivity Logs,” AAPG Bulletin 74, 1777-1794 (1990), which is incorporated by reference herein in its entirety. The Delta Log R method relies on first-order rock physics that predicts reduced vertical acoustic velocities (due to the presence of kerogen) and increased horizontal resistivities (reflecting kerogen content and in-situ generation of hydrocarbons) in organic-rich rocks as functions of TOC and LOM. The present invention is a method to perform Delta Log R analyses in the absence of a well at the point under investigation, using seismic and electromagnetic geophysical data measured remotely.
Hydrocarbon source rock mapping in untested (un-drilled) basins, and in unexplored areas of explored basins, has been addressed primarily by geological interpretation of seismic reflection patterns (K. M. Bohacs, 1998, “Contrasting Expressions of Depositional Sequences in Mudrocks From Marine to Non-Marine Environs,” Shales and Mudstones I, Schweizerbart'sche Verlagbuchhandlung, pp. 33-78); by basin history and evolution modeling, and by basin analog and environment-of-deposition studies (Bohacs et al., “Production, Destruction, and Dilution—The Many Paths to Source-Rock Development,” SEPM Special Publication 82, 61-101 (2005); S. Creaney and Q. R. Passey, op. cit. 1993). However, these approaches have large uncertainties, and generally have not definitely identified the presence of adequate source rocks. Source rocks typically occupy a relatively small fraction of total shale volume, and may not have clear seismic reflection boundaries within the shale interval, so their detection can be difficult. Known source rocks of commercial importance vary in thickness within a common range of about 30 to 300 meters. What is needed is a remote geophysical method, having at least moderate vertical resolution and accuracy that can identify and characterize source rocks in this thickness range, and that has a useful subsurface/sub-seafloor depth of investigation to 3000 meters or more. Given the increasingly limited commercial access to sedimentary basins due to several factors, remotely identifying source rock in unexplored areas would have substantial benefits for worldwide exploration opportunities. The present invention's method for combining seismic and electromagnetic geophysical data satisfies this need.
1. Delta Log R Borehole Method
Delta Log R is a proven technique for identifying and calculating TOC in organic-rich rocks using well logs. (Passey et al., supra; see also Creaney and Passey, “Recurring Patterns of Total Organic Carbon and Source Rock Quality Within a Sequence Stratigraphic Framework,” AAPG Bulletin 77, 386-401 (1993); Meyer and Nederlof, “Identification of Source Rock on Wireline Logs by Density/Resistivity and Sonic Transit Time/Resistivity Crossplots,” AAPG Bulletin 68, 121-129 (1984); Meissner, “Petroleum Geology of the Bakken Formation Williston Basin, North Dakota and Montana,” in The Economic Geology of the Williston Basin, Montana Geological Society, 1978 Williston Basin Symposium, 207-227; and “Method for Evaluating the Content of Organic Matter of Sedimentary Rocks From Data Recorded in Wells by Logging Sondes,” French Patent No. 2,674,961 to Ros, Carpentier and Huc (Apr. 8, 1991)) The method employs the overlay of a log response scaled to represent total porosity (usually the sonic transit-time log) onto a scaled resistivity curve that preferably measures deep formation resistivity. The log resistivity that is measured is usually assumed to be the horizontal component, due primarily to the design of the borehole tool. Conversely, the log sonic transit time that is measured is usually assumed to be the vertical component, again due primarily to the design of the borehole tool. The response scaling is performed using baselines for the logs in non-source clay-rich rocks such as shales, identified using primarily the gamma-ray (GR) log. In the common practice of the Delta Log R art, the transit-time curve and the resistivity curve are scaled so that their relative magnitude is −100 microseconds/foot of transit time per two logarithmic resistivity cycles. In low-TOC water-wet porous rocks, the two curves are very nearly parallel and can be closely overlain, since both respond to porosity. But in high-TOC source rocks (or in reservoirs that contain hydrocarbons) a separation occurs between these curves due to two main effects: 1) the porosity curve responds to the presence of low-density low-velocity kerogen, and 2) the resistivity curve responds to the formation fluid. Level of organic metamorphism (LOM) is estimated in several ways, including vitrinite reflectance of subsurface samples and estimates of thermal and burial history. LOM describes thermal maturity (metamorphism) of sedimentary organic matter during burial—the cumulative effect of exposure to elevated temperature. It is a numerical scale (zero to twenty) which is applicable to the entire thermal range of generation and destruction of petroleum. When maturity is low and no hydrocarbons have been generated, the curve separation is caused only by the porosity response to low density and/or low velocity TOC. Conversely, when maturity is high in such organic-rich rocks or in hydrocarbon-bearing reservoirs, the resistivity response increases due to the generated hydrocarbons.
FIGS. 1A-C depict the solid and fluid components in hydrocarbon source and non-source rocks. Organic-rich rocks are assumed to be composed of three components: (1) the rock matrix, (2) the solid organic matter, and (3) the fluid(s) filling the pore space, typically water or oil/gas. Non-source rocks are composed primarily of only two components: the matrix and the fluid filling the pore space (FIG. 1A). In immature source rocks, solid organic matter and rock matrix make up the solid fraction, and formation water fills the pore space (FIG. 1B). As the source rock matures, a portion of the solid organic matter is transformed to liquid (or gaseous) hydrocarbons, which move into the pore space, displacing the formation water (FIG. 1C). The magnitude of the curve separation in non-reservoir rock intervals is then calibrated to TOC and LOM from core samples and from empirical and/or statistical relationships from the same or similar sedimentary basins. The Delta Log R method can thus be used to assess organic richness of subsurface formations in a wide variety of facies and lithologies as depicted in FIGS. 2 and 3. Note that the gamma ray log in FIG. 2, which aids in interpretation of the depth intervals and confirms identification and elimination from the analysis of reservoir intervals, would normally not be available in situations where the Remote Δ Log R of the present invention is applied, because it is the organic-rich source intervals that are of interest.
In applications of Delta Log R, the amplitudes of the transit-time curve (21 in FIG. 2) and the resistivity curve (22) are scaled such that their relative scaling is −100 μsec/ft (−328 μsec/m) per two logarithmic resistivity cycles (i.e., a ratio of −50 μsec/ft or −164 μsec/m to one resistivity cycle), as is indicated by the ΔT and Δ Log R scales at the bottom of FIG. 2. The two curves are overlain, i.e. baselined, in fine-grained, “non-source” rock intervals such as zones A and E in FIG. 2. A baseline condition exists when the two curves “track” or directly overlie each other over a significant depth range. Typically, zone A may extend upward for a considerable distance, but for display purposes, this is truncated in FIG. 2 leaving only the lower portion. The discovery underlying Delta Log R was that after the aforementioned scaling and baselining, the irregularities of intervals such as A and E match up very well. With the baseline established, organic-rich intervals can be recognized by separation and non-parallelism of the two curves, such as the intervals labeled “immature source” and “mature source” in FIG. 2. The separation between them, designated as Δ log R in FIG. 2, can be measured at each depth increment. It may be noted that both zones C and F exhibit significant Δ Log R separation. It is difficult to differentiate the two zones from the sonic log alone, but the resistivity log distinguishes them. In zone C, the resistivity log shows no deviation from the baseline, but in zone F the resistivity increases, indicating that hydrocarbons have displaced water in the pore spaces, thereby increasing resistivity. Thus, zone F is mature source rock whereas zone C is immature source rock.
The Δ Log R separation is linearly related to TOC and is a function of maturity. Using a Δ Log R calibration diagram such as FIG. 3, the Δ Log R separation can be transformed directly to a quantitative estimate of TOC if the maturity (in level of organic metamorphism units, LOM; see for example Hood et al., 1975) can be determined or estimated. In practice, LOM is obtained from a variety of sample analyses (e.g. vitrinite reflectance, thermal alteration index, or Tmax from RockEval pyrolysis), or from estimates of burial and thermal history. If the maturity (LOM) is incorrectly estimated, the absolute TOC values will be somewhat in error, but the vertical variability in TOC will be correctly represented. With reference to FIG. 3, the dark line 31 should be used for maturity less than LOM 6. Immature source rock has LOM of 6 to 7 or less. The LOM range of approximately 7-11 indicates mature source rock, meaning that oil or gas should be present in the vicinity. Above LOM 11 is considered over-mature source rock; an example is shale gas. The Delta Log R method works even in the over-mature source rock range, and therefore, as will be explained below, so does the present inventive method. Experience has shown that an LOM in the 10-10.5 range should be used for LOM 11 or greater for estimating TOC; i.e., the portion of FIG. 3 below LOM≈10.5 should not be used. Moreover, the Delta Log R method is also known to work on coals except that that the calibration of Δ Log R to TOC will not be the same as for organic-rich shales. The coals are still easily recognized, but the Delta Log R method will under-predict TOC in a coal if the calibration of FIG. 3 is used—e.g., Delta Log R might predict TOC will be 20-30 wt %, whereas, the real TOC may be 60-80 wt %. Coal covers the entire maturity scale: LOM<1 is called peat; LOM in the range 1-4.5 is called lignite coal; LOM in the range 4.5-7 is called sub-bituminous coal; LOM in the range 7.5-13 is called bituminous coal; and LOM>13 is called anthracite coal. In the claims, the term hydrocarbon source rock potential will be understood to include coal potential.
For the example in FIG. 2, the maximum Δ Log R separation is approximately 0.7 of a logarithmic resistivity cycle (i.e. Δ Log R=0.7). If the LOM is 6-7, this can be seen from FIG. 3 to correspond to a TOC value of approximately 12%. In this manner, a TOC value depth profile may be calculated from FIGS. 2 and 3.